A ground-breaking study involving leading utilities and the Australian Renewable Energy Agency has suggested that Australia’s largest battery storage array could be installed at a South Australian wind farm.

The study – Energy Storage for Commercial Renewable Integration in South Australia (ESCRI-SA) – looks at a range of possibilities for non-hydro storage in South Australia and concludes that a 10MW, 20MWh lithium-ion battery storage facility next to the 91MW Wattle Valley wind farm on the Yorke Peninsula is the best option.

Wattle Point wind farm. Photo credit: David Clarke.

It is not yet clear that the project will go ahead in that form – questions about financing, the economics of the project and the ability of ARENA to maintain grant funding have yet to be resolved – but it seems certain that the project will go ahead in some form, possibly as a reconfigured 30MW, 8MWh facility.

South Australia finds itself at the cutting edge of the world’s shift to renewable energy, with its wind farms and rooftop solar expected to account for around half of total demand by the end of the year.

While the Australian Energy Market Operator says this should pose no problems for the local grid – even after the closure of the state’s last coal-fired power station within a few weeks – eventually battery storage will have to be integrated into the grid to ensure stability.

“There is no better place to demonstrate this than in South Australia, which has world leading levels of intermittent wind and solar PV generation relative to demand,” the study says. Within a decade, rooftop solar may account for all demand on some days, and there is another 3,000MW of wind projects in the pipeline.

The 368-page ESCRI study – partnered by ElectraNet, AGL Energy and Worley Parsons – says that while there are no immediate problems, there is a sense of urgency because battery storage is emerging quickly and the market is simply not prepared.

“It is hard to see a long-term future which does not involve energy storage in some form,” it notes, adding that the issues arising in South Australia are likely to emerge in other states as renewable energy penetration increases; meaning reliance on traditional inter-connector network solutions may become less effective.

ARENA admits that the report’s conclusions around the economics of the project were disappointing, because it found that it would need grant funding of around $14 million, or nearly two-thirds the cost of the project.

But it, and the consortium members, expect this to turn around soon. For one, the discussions with the battery storage industry found that the market is still very immature, and battery storage is a complex business. In other words, the battery storage industry is still learning how to configure its gear to suit the network and its major players.

Secondly, the costs of battery storage are expected to fall quickly, with nearly all of the battery storage providers indicating that prices would fall by half in the next few years.

Thirdly, and perhaps most significantly, is that the market for services that battery storage can provide to the network is also immature.

These services include balancing the output of wind and solar farms, keeping the lights on in a blackout, reducing transmission losses, and providing frequency services to keep the grid stable.

Once these services are better understood, and better valued – and this might need adjustments to regulations and market signals – then the economics of battery storage are likely to be clear.

Indeed, the report notes that frequency control – and the ability to keep the lights on in the event that the state’s interconnector to Victoria goes out – could be critical.

It says that one project is not enough to do this job, but if enough energy storage devices were installed, then this could reduce market fuel costs (from gas generators, for instance) and avoid the loss of all supply to grid-connected consumers. This is particularly important, in light of the state’s recent black-out and the problems created by fossil fuel generators in the attempted re-start.

Certainly, the consortium members are keen for the project to go ahead, and say that without it, Australia might be left behind just when it should be seizing the opportunity of leading the pack.

“Unlike Australia, other countries have particular policy drivers which are leading to storage take-up, with motives likely to include the lowering of integration costs of renewables, the gaining of experience with a likely disruptive technology and the driving of a local energy storage industry,” the study notes.

It cites the Californian Independent System Operator (ISO), which operates in one of the most active energy storage markets driven by its policy mandate for more than 2GW of battery storage, designed specifically to ensure it keeps on top of renewable integration.

“In the absence of such policy drivers and any current roadmap, Australia must make prudent investments to keep pace,” the ESCRI report notes. “This also supports the case to continue exploration of the storage product but provides more incentive to maximise the business case – that is, leverage the most from that investment.”

Wattle Point and the nearby Dalrymple sub-station was chosen because it is a kind of microcosm of the state’s grid. It’s at the end of the network, it has large penetration of renewables, and there is a possibility of it being “islanded” – meaning that it will rely on local resources, including battery storage, to keep the lights on.

It also offers advantages to both ElectraNet, which runs the main transmission line, and AGL. Assets owned by distribution network SA Power Networks were not considered, even though areas such as Kangaroo Island and Victor Harbour could also be suitable.

Expressions of interest from 42 international parties were received, and 17 formal proposals, including technologies such as lithium-ion, sodium-sulphur and advanced lead acid batteries; molten salt heat storage; hydrogen generation and storage; and a number of different flow batteries. Project sizes ranged from 10-20MW and 20MWh to 200MWh.

In the end, the consortium crunched the numbers in a detailed study of a 10MW- 20MWh lithium-ion project at Dalrymple.

As for the next stage, the project partners are keen not to reduce the scale of the project too much, otherwise it will limit its impact, and may not allow the parallel services of market and network value to be realised effectively at the same time.

It may not even choose lithium-ion, but rather a hybrid of energy storage technologies through a single interface, if available.

“The consortium remains agnostic to which energy storage technology is used and will pursue that which delivers the optimum business case, although the project is really more about application than technology.”

You would think that while they are at it they would throw in a decent size bank of Aquion batteries – no moving parts makes them worthwhile looking at and to compare with Redflow.

Jonathan Prendergast

A challenge for grid support battery projects is revenue. It can certainly provide value and avoid costs, but capturing that value through a revenue model in the current market setup requires regulatory change or innovation.